In hydrocarbon production, there is often a desire to accurately track fluids within a well. This is useful for the efficient running of a well, for example to determine how various portions of the well are contributing to the overall production. In addition, it may be that different entities own different reservoirs which are accessed by a common well bore. Understanding fluid flow in the well allows the earnings of particular owners to be determined according to the volume of hydrocarbon produced from that reservoir.
As will be familiar to the skilled person, the desired hydrocarbon (oil, gas, etc), is not the only fluid in a well. Other fluids, such as water, will also be found. Indeed, water control is often a key concern for well operators. The water must be separated out from the desired hydrocarbon, before usually being chemically treated and returned to the ground, all of which adds to operational costs. Where the water volume exceeds a certain level, a well may become economically unviable. In certain gas wells, water may also inhibit or stop flow where the gas pressure is too low to push the water out.
Access from a wellbore to a hydrocarbon reservoir can be via one or more perforations in the wall of a wellbore casing. Where the volume of water inflow from a particular perforation is significant (or significant in comparison to the amount of hydrocarbon), the perforation may be deemed to have become ‘watered out’, and blocking off the perforation may increase the well profitability. However, it is often difficult to determine which perforations are contributing excessively to the water content in a well.
Known production logging tools to monitor flow within a well include flow meters such as turbine meters, or ‘spinners’, which are placed inside a functioning well to measure the velocity of fluid flow based on the speed of rotation of a spinner. Unfortunately, the relationship between the spinner's speed of rotation and the actual fluid flow are complex due to friction and fluid viscosity and at lower flow velocities a spinner may not function at all. Also, such spinners interfere with flow and often provide confusingly different measurements when being inserted and withdrawn. Further, it is not easy to distinguish between different fluids using spinners.
There are other flow meters, such as gas orifice meters, ultrasonic flow meters, Coriolis meters, etc. which have associated advantages and drawbacks. However, all such meters are subject to damage from their hostile operating environment, require careful calibration and impede flow.
In addition, multiphase meters, which are capable of distinguishing between liquids and gases (which could be gas, oil and/or water) are also known. Again, such meters are subject to harsh environments and may not be able to isolate the contributions from individual perforations.
All such methods require well intervention, with associated safety concerns, and well down-time, and are only capable of providing a ‘snapshot’ in time. Using optical fibres to estimate the temperature of a well and imply flow rates therein is also known, for example from U.S. Pat. No. 6,618,677. However, the method described therein relies on a complex model and requires a well ‘shut in’ before the method may be employed.